Method and system for increasing effective data rate of telemetry for wellbore construction

ABSTRACT

Methods and systems for predicting downhole measurement data at the earth surface include predicting a first estimate value of a property of interest using a first processor in a downhole tool using a first predictor and predicting a second estimate value of the property of interest using a second processor of a surface unit and using a second predictor, the second predictor including identical data processing as the first predictor. A measurement value of the property of interest is obtained using a sensor arranged in the downhole tool. The first processor compares the measurement value with the first estimate value and determines if the measurement value is within a predetermined threshold relative to the first estimate value. In response to the measurement value being within the predetermined threshold of the first estimate value, a wellbore operation based on the second estimate value is performed using the second processor.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of an earlier filing date from U.S. Provisional Application Ser. No. 63/392,286, filed Jul. 26, 2022, the entire disclosure of which is incorporated herein by reference.

BACKGROUND

The present disclosure relates to telemetry systems and, more particularly, to telemetry systems for communicating from a downhole location (e.g., within a borehole) to another location within the borehole or at the surface and estimating and/or processing of data obtained using downhole sensors.

Telemetry in downhole operations is used for communication data and/or instructions between a downhole location (e.g., downhole tools) and other downhole tools and/or the surface. Telemetry and data transmission may be through mud-pulse telemetry, wireline data communication, wired-pipe systems, electromagnetic transmission (e.g., through a formation), or the like. However, due to the nature of downhole operations, bandwidth is limited, which results in low bandwidth for uplink and downlink communication. This is particularly true for, but not limited to, while-drilling operations. The amount and quality of drilling service data transmissions may be limited due to low data density and/or bandwidth limitations. For example, borehole quality may be compromised through avoidance of steering downlinks in order to have a faster drilling operation (e.g., formation evaluation may be compromised as data rate of multiple petrophysical measurements may be low). That is, due to the limited bandwidth, transmissions of controls or instructions from the surface may be limited to avoid delays in a drilling operation. Such delays may be impacted by limited uplink transmissions when data collected downhole is transmitted uphole. One solution to such limited bandwidth is to use wired-pipe systems, but due to the nature of wired pipe, the costs associated with such a solution may be prohibitive. Accordingly, improved systems or methods for telemetry may be desirable.

SUMMARY

According to some embodiments, methods for predicting downhole measurement data at the earth surface are provided. The methods include predicting a first estimate value of a property of interest using a first processor arranged in a downhole tool in a borehole, the first processor executing a first predictor, predicting a second estimate value of the property of interest using a second processor arranged in a surface unit at the earth surface and outside the borehole, the second processor executing a second predictor, the second predictor including identical data processing as the first predictor, such that when the same input is provided to each of the first predictor and the second predictor, the first estimate value predicted at the first processor is equal to the second estimate value predicted at the second processor, obtaining, by a sensor, a measurement value of the property of interest, wherein the sensor arranged in the downhole tool, comparing, at the first processor, the measurement value with the first estimate value predicted by the first predictor, determining if the measurement value is within a predetermined threshold relative the first estimate value, and performing a wellbore operation based on the second estimate value of the property of interest, using the second processor, in response to the measurement value being within the predetermined threshold of the first estimate value.

According to some embodiments, data prediction systems for use with downhole operations are provided. The data prediction systems include a sensor configured to obtain a measurement value of a property of interest, the sensor arranged on a downhole tool located in a borehole, a first processor arranged in the downhole tool and configured to receive the measurement value from the sensor, and a second processor arranged in a surface unit at the earth surface and outside the borehole. The first processor is configured to execute a first predictor, receive the measurement value of interest from the sensor, predict a first estimate value of the property of interest by executing the first predictor, compare the first estimate value with the measurement value, and determine if the measurement value is within a predetermined threshold from the first estimate value. The second processor is configured to execute a second predictor, predict a second estimate value of the property of interest by executing the second predictor, and perform a wellbore operation based on the second estimate value when the measurement value is within the predetermined threshold from the first estimate value. The first predictor and the second predictor are configured to perform identical data processing such that when the same input is provided to each of the first predictor and the second predictor, the predicted first estimate value is equal to the predicted second estimate value.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

FIG. 1 depicts a schematic illustration of a wellbore operation system that can incorporate embodiments of the present disclosure;

FIG. 2 depicts a block diagram of a processing system, which can be used for implementing more embodiments of the present disclosure;

FIG. 3 is a schematic illustration of a system in accordance with an embodiment of the present disclosure;

FIG. 4 is a schematic illustration of an example process in accordance with an embodiment of the present disclosure;

FIG. 5 is a schematic illustration of a system in accordance with an embodiment of the present disclosure; and

FIG. 6 is a flow process in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures. Modern bottomhole assemblies (BHAs) are composed of several distributed components, such as sensors and tools, with each component performing data acquisition and/or processing of a special purpose. During a drilling operation, sensors and detectors may be used to determine the nature of a surrounding formation and/or to determine if the location of the borehole is passing through an expected formation and/or within a specification formation (e.g., for production purposes). Such sensors and detectors may also or alternatively be used to determine physical properties relevant for drilling operations, such as, and without limitation, pressure, temperature, mechanical loading (e.g., accelerations, bending moments, torsional moments, axial forces, etc.), or directional information, such as drift/inclination or direction/azimuth.

FIG. 1 illustrates an embodiment of a system 100 for performing an energy industry operation (e.g., subsurface drilling, measurement, stimulation, and/or production). The system 100 includes a borehole string 102 that is shown disposed in a well or borehole 104 that penetrates at least one earth formation 106 during a drilling or other downhole operation. As described herein, “borehole” or “wellbore” refers to a hole that makes up all or part of a drilled well. It is noted that the borehole 104 may include vertical, deviated, and/or horizontal sections, and may follow any suitable or desired path. As described herein, “formations” refer to the various features and materials (e.g., geological material) that may be encountered in a subsurface environment and surround the borehole 104.

The borehole string 102 is operably connected to a surface structure or surface equipment such as a drill rig 108, which includes or is connected to various components such as a surface drive 110 (also referred to as top drive) and/or rotary table 112 for supporting the borehole string 102, rotating the borehole string 102, and lowering string sections or other downhole components into the borehole 104. In one embodiment, the borehole string 102 is a drill string including one or more drill pipe sections 114 that extend downward into the borehole 104 and is connected to one or more downhole components (downhole tools), which may be configured as a bottomhole assembly (BHA) 116. The BHA 116 may be fixedly connected to the borehole string 102 such that rotation of the borehole string 102 causes rotation of the BHA 116.

The BHA 116 includes a disintegrating device 118 (e.g., a drill bit), which in this embodiment is driven from the surface, but may be driven from downhole (e.g., by a downhole mud motor or turbine). The system 100 may include components to facilitate circulating fluid 120, such as drilling mud, through an inner bore of the borehole string 102 and an annulus between the borehole string 102 and a wall of the borehole 104. For example, in this illustrative embodiment, a pumping device 122 is located at the surface to circulate the fluid 120 from a mud pit or other fluid source 124 into the borehole 104 as the disintegrating device 118 is rotated (e.g., by rotation of the borehole string 102 and/or a downhole motor).

In the illustrative embodiment shown in FIG. 1 , the system 100 can include a steering assembly 126 configured to steer or direct a section of the borehole string 102 and the disintegrating device 118 along a selected path. The steering assembly 126 may have any configuration suitable to direct or steer the drill string 102. Examples of steering assemblies include, without limitation, steerable motor assemblies (e.g., bent housing motor assemblies), turbines, and rotary steerable assemblies or systems.

In one non-limiting embodiment, the steering assembly 126 is configured as a rotary steering assembly forming the BHA 116 or part of the BHA 116. The steering assembly 126 includes a non-rotating or slowly-rotating sleeve 128 that includes one or more radially extendable pads 130 (extendable in a direction perpendicular to a longitudinal axis of the sleeve). The pads 130 may be located at different circumferential locations on the sleeve 128 and are adjustable individually or in combination to deflect the disintegrating device 118 by engaging the wall of the borehole 104.

The system 100 may also include a controller configured to operate or control operation of the pads 130 based on directional information derived from directional sensors located in the BHA 116 and/or the borehole string 102. The directional sensor(s) may be arranged at, in, or near the steering assembly 126. The directional sensor(s) can include one or more gyroscopes (e.g., gyroscope sensors or earth rate sensor sensors), and also include one or more magnetometers (i.e., magnetic field sensors) and/or one or more accelerometers (e.g., acceleration sensors and/or gravitational sensors).

In one embodiment, the system 100 includes one or more sensor assemblies 132 configured to perform measurements of parameters related to position and/or direction of the borehole string 102, the disintegrating device 118, and/or the steering assembly 126. As shown in FIG. 1 , the sensor assemblies 132 may be located at one or more of various locations, such as on the sleeve 128, at or near the disintegrating device 118, and/or on other components of the borehole string 102 and/or the BHA 116. For example, a sensor assembly 132 can be located on one or more stabilizer sections 134 of the steering assembly 126. The sleeve 128 may be coupled to the borehole string 102 by a bearing assembly or other mechanism that allows rotation of the sleeve independent of the rotation of the borehole string, as will be appreciated by those of skill in the art.

The system 100 may include one or more of various tools or components configured to perform selected functions downhole such as performing downhole measurements/surveys (e.g., formation evaluation measurements, directional measurements, etc.), facilitating communications (e.g., mud pulser, wired pipe communication sub, etc.), providing electrical power and others (e.g., mud turbine, generator, battery, data storage device, processor device, modem device, hydraulic device, etc.). For example, the steering assembly 126 can be connected to one or more sensor devices, such as a gamma ray imaging tool 136. Such gamma ray imaging tool 136 may be used to measure formation density, for example.

In one embodiment, the system 100 includes a measurement device such as a logging while drilling (LWD) tool (e.g., for formation evaluation measurements) or a measurement while drilling (MWD) tool (e.g., for directional measurements), generally referred to as while-drilling tool 138. Examples of LWD tools include nuclear magnetic resonance (NMR) tools, resistivity tools, gamma (density) tools, pulsed neutron tools, acoustic tools, and various others. Examples of MWD tools include tools measuring pressure, temperature, or directional data (e.g., magnetometer, accelerometer, gyroscope, etc.). The steering assembly 126 or the system 100 can include other components, such as a telemetry assembly (e.g., mud pulser, wired pipe communication sub, etc.) or other downhole and/or surface components, systems, or assemblies.

In one non-limiting embodiment, during drilling, the sleeve 128 does not rotate or rotates at a rate that is less than the rotational rate of the disintegrating device 118 and other components of the steering assembly 126 and rotary table 112 or surface drive 110. The rate of rotation of the sleeve 128 may be denoted herein as “slow rotation.” It is noted that “slow” rotation is intended to indicate a rotational rate that is less than the drilling rotational rate and is not intended to be limiting to any specific rate. A “slowly-rotating” sleeve is a sleeve that rotates at the slow rotation rate.

The sleeve 128 can rotate at any suitable slow rotation rate that is less than the drilling rotation rate. In one embodiment, slow rotation of the sleeve 128 is a rate between about 1 and 10 revolutions per hour (RPH). In one embodiment, slow rotation is between about 10 and 50 RPH (60°/minute and 300°/minute). In yet another embodiment, slow rotation is about 1 and 50 RPH (6°/minute and 300°/minute).

One or more downhole components and/or one or more surface components may be in communication with and/or controlled by a processor such as a downhole processing unit 140 and/or a surface processing unit 142. The downhole processing 140 may be parts of the BHA 116 or may be otherwise arranged on or part of or disposed on the borehole string 102. The surface processing unit 142 (and/or the downhole processing unit 140) may be configured to perform functions such as controlling drilling and steering, controlling the flow rate and pressure of the fluid 120, controlling weight on bit (WOB), controlling rotary speed (RPM) of the rotary table 112 or the surface drive 110, transmitting and receiving data, processing measurement data, and/or monitoring operations of the system 100. The surface processing unit 142, in some embodiments, includes an input/output (I/O) device 144 (such as a keyboard and a monitor), a processor 146, and a data storage device 148 (e.g., memory, computer-readable media, etc.) for storing data, models, and/or computer programs or software that cause the processor to perform aspects of methods and processes described herein.

In one non-limiting embodiment, the surface processing unit 142 is configured as a surface control unit which controls a wellbore operation and/or various parameters such as rotary speed (RPM), weight-on-bit, fluid flow parameters (e.g., pressure and flow rate), directional steering control of a rotary steering assembly, and/or other parameters or aspects of the system 100, such as data processing and/or data log generation. The wellbore operation may involve a human operator or may be performed automatically without interference of a human operator. The downhole processing unit 140, in some embodiments, may be a directional measurement controller or other processing device that controls aspects of operating the sensor assemblies 132, acquiring measurement data, and/or estimating directional parameters. The downhole processing unit 140 may also include functionality for controlling operation of the steering assembly 126 and/or other downhole components, assemblies, or systems. In one non-limiting embodiment, the method and processes described herein may be performed in the downhole processing unit 140 located within the borehole string 102 or the BHA 116.

In the embodiment of FIG. 1 , the system 100 is configured to perform a drilling operation and a downhole measurement operation, and the borehole string 102 is a drill string. However, embodiments described herein are not so limited and may have any configuration suitable for performing an energy industry operation that includes or can benefit from directional measurements (e.g., completion operation, fracturing operation, production operation, re-entry operation, etc.).

It is understood that embodiments of the present disclosure are capable of being implemented in conjunction with any other suitable type of computing environment now known or later developed. For example, FIG. 2 depicts a block diagram of a processing system 200 (e.g., surface processing unit 142 and/or downhole processing unit 140 of FIG. 1 ), which can be used for implementing the techniques described herein. In examples, the processing system 200 has one or more central processing units 202 a, 202 b, 202 c, etc. (collectively or generically referred to as processor(s) 202 and/or as processing device(s) 202). In aspects of the present disclosure, each processor 202 can include a reduced instruction set computer (RISC) microprocessor. The processor(s) 202, as shown, are coupled to system memory (e.g., random access memory (RAM) 204) and various other components via a system bus 206. Read only memory (ROM) 208 is coupled to the system bus 206 and can include a basic input/output system (BIOS), which controls certain basic functions of the processing system 200.

Further illustrated in FIG. 2 are an input/output (I/O) adapter 210 and a network adapter 212 coupled to the system bus 206. The I/O adapter 210 can be a small computer system interface (SCSI) adapter that communicates with a memory, such as a hard disk 214 and/or a tape storage drive 216 or any other similar component(s). The I/O adapter 210 and associated memory, such as the hard disk 214 and/or the tape storage device 216, may be collectively referred to herein as a mass storage 218. An operating system 220 for execution on the processing system 200 can be stored in the mass storage 218. The network adapter 212 may be configured to interconnect the system bus 206 with an outside network 222 enabling the processing system 200 to communicate with other systems and/or remote systems (e.g., internet, extranet, and/or cloud-based systems).

A display (e.g., a display monitor) 224 is connected to the system bus 206 by a display adaptor 226, which can include, for example, a graphics adapter to improve the performance of graphics intensive applications and a video controller. In one aspect of the present disclosure, the adapters 210, 212, and/or 226 can be connected to one or more I/O busses that are connected to system bus 206 via an intermediate bus bridge (not shown), as will be appreciated by those of skill in the art. Suitable I/O buses for connecting peripheral devices such as hard disk controllers, network adapters, and graphics adapters typically include common protocols, such as the Peripheral Component Interconnect (PCI). Additional input/output devices are shown connected to the system bus 206 via a user interface adapter 228 and the display adapter 226. For example, as shown, a keyboard 230, a mouse 232, and speaker 234 can be interconnected to the system bus 206 via the user interface adapter 228, which can include, for example, a Super I/O chip integrating multiple device adapters into a single integrated circuit.

In some aspects of the present disclosure, and as shown, the processing system 200 includes a graphics processing unit 236. Graphics processing unit 236 may be a specialized electronic circuit designed to manipulate and alter memory to accelerate the creation of images in a frame buffer intended for output to a display (e.g., display 224). In general, the graphics processing unit 236 is very efficient at manipulating computer graphics and image processing and has a highly parallel structure that makes it more effective than general-purpose CPUs for algorithms where processing of large blocks of data is done in parallel.

Thus, as configured herein, the processing system 200 includes processing capability in the form of processors 202, storage capability including system memory (e.g., RAM 204 and mass storage 218), input means such as keyboard 230 and mouse 232, and output capability including speaker 234 and display 224. In some aspects of the present disclosure, a portion of system memory (e.g., RAM 204 and mass storage 218) may be configured to collectively store an operating system (e.g., operating system 220) to coordinate the functions of the various components shown in the processing system 200.

It will be appreciated that the processing system 200 of FIG. 2 is presently described as a surface system (e.g., surface processing unit 142 of FIG. 1 ). However, it will be appreciated that similar electronic components may be employed in downhole systems (e.g., as part of a BHA and/or downhole processing unit 140). In such configurations, certain features of the processing system may be omitted. For example, in a downhole BHA system, the user interface components may be omitted. Further, the system bus may be arranged to span multiple different downhole components and the network connection may be a communication means (e.g., telemetry, wired connection, wireless connection, or the like) that is configuration to enable communication between a surface system and the downhole BHA system.

The processing system 200 may be in communication with one or more downhole components through a communication connection, such as mud-pulse telemetry or the like. In some configurations, as mentioned, wired connections may be employed, but use of wired pipe may be cost-prohibitive. As such, lower bandwidth solutions are still relied upon for communication between downhole components and other downhole components or with components at the surface. It will be appreciated that communication between two downhole components may be through a wired connection and may not require telemetry. However, a substantial portion of downhole communication employs telemetry transmission and the bandwidth of telemetry-based communication is limited. A low bandwidth for uplink and/or downlink can result in delays in a drilling operation. For example, due to the low bandwidth, it is difficult (e.g., time consuming) to transmit information (including data and/or commands) between the surface and downhole components. As such, during an active drilling operation, it is not desirable to delay drilling for the purpose of data transmission, particularly if the data being transmitted merely confirms that a drilling trajectory or drilling plan is being maintained (e.g., no issues present).

In view of the high cost of wired solutions, the delays associated with telemetry, the bandwidth restrictions associated with telemetry, and in view of other considerations, embodiments of the present disclosure are directed to providing improved telemetry communication. For example, in accordance with some embodiments, two similar or identical systems are arranged at two separate locations (e.g., one downhole and one at the surface) and configured to analyze data and make determinations regarding transmissions of data. In one non-limiting example, a downhole unit may be configured to estimate a next-collected data point. When the next-collected data point is collected, such as by a tool or sensor, the downhole unit can check to see if the collected data matches the estimate, and if there is a match, the downhole unit can cause no transmission of the data. At the same time, a surface unit, with the same processing as the downhole unit (and same starting information), may check to see if data is received in a given period of time, and if no data is received, then the surface unit may assume that the collected data matches the estimate, and update the information stored at the surface unit based on this lack of received signal.

Referring now to FIG. 3 , a schematic illustration of a system 300 for performing an energy industry operation (e.g., subsurface drilling, measurement, stimulation, and/or production) is shown. The system 300 may be similar to that shown and described above, and thus certain feature may not be illustrated or described again. The system 300 includes a surface system 302 and a downhole system 304. The surface system 302 includes a surface control unit 306 and a pump system 308 coupled to a mud pit 310 or the like and configured to generate mud pulses for telemetry purposes based on control from the surface control unit 306. The downhole system 304 is disposed in a wellbore 312 formed in the earth 314. The downhole system 304 includes a string 316 with a bottomhole assembly (“BHA”) 318 arranged at an end of the string 316. The BHA 318 includes a bit 320 (e.g., drill bit, disintegrating device, or the like) on an end thereof and configured to cut, break, or disintegrate material of the earth 314 to drill and form the wellbore 312.

The BHA 318 includes one or more downhole tools 322, 324 and a downhole control unit 326. Although FIG. 3 illustrates a particular arrangement of components, those of skill in the art will appreciate that the order and arrangement of parts may be varied depending on the particularly needs of a system and/or the BHA itself. Thus, the illustrative configuration is merely for explanatory purposes and is not intended to be limiting. The downhole tools 322, 324 may be formation evaluation tools, BHA monitoring tools, steering or geosteering tools, or the like, as will be appreciated by those of skill in the art. The downhole control unit 326 may be configured in communication with the downhole tools 322, 324 and/or the bit 320 and configured to receive information for processing and/or communication to the surface (e.g., to the surface control unit 306). The downhole control unit 326 may include (or be in communication with) a pulser or the like that is configured to generate mud pulses in a drilling fluid (e.g., provided from the mud pit 310 and the pump system 308) to transmit data from the BHA 318 to the surface control unit 306.

Each of the surface control unit 306 and the downhole control unit 326 may be configured to process data received from external sources (e.g., from the downhole tools 322, 324, from sensors at the surface or downhole, or the like). Data that is collected downhole is typically transmitted from the downhole control unit 326 to the surface control unit 306 by telemetry. As discussed above, such telemetry may be subject to bandwidth limitations. The bandwidth limitations may limit the amount of data (e.g., collected data, commands, feedback information, etc.) that may be transmitted from the downhole control unit 326 to the surface control unit 306 (or vice versa). For a given downhole instrument or operation, certain data may be collected and processed. The data may include instructions or commands transmitted from the surface control unit 306 and/or may include information collected by the tool that may be part of the downhole operation. Prior to transmission of data, either from the surface or from downhole, some amount of pre-processing of the data may be performed, such as to pre-filter, organize, flag, or package, or otherwise process such data. Accordingly, each of the surface control unit 306 and the downhole control unit 326 may include one or more processors and associated memory and other electrical components to perform such processing.

In accordance with an embodiment of the present disclosure, each of the surface control unit 306 and the downhole control unit 326 is programmed with a predictor (e.g., a surface predictor, a downhole predictor, etc.). As used herein, a predictor is a piece of software code that may be stored on memory, within a processor, or otherwise stored and associated with a control logic, processor, general computer, PCB, or the like. The predictors, described herein, may be processes that are executed by an associated processor. These processors can be configured to perform other tasks, such as controlling telemetry or the like, or may be dedicated processors configured to perform the processes described herein. In accordance with some embodiments, and without limitation, the predictors may include one or more of linear regressions, logistic regressions, decision tree algorithms, gradient boosted models, neural networks, and/or combinations thereof or the like.

For example, and in accordance with embodiments of the present disclosure, the predictor(s) may be executed by one or more processor, such as a processor in the surface control unit 306 and/or a processor in the downhole control unit 326. The predictors of each of the surface control unit 306 and the downhole control unit 326 are substantially identical, such that when the same input value or data is input to the respective control units 306, 326, the output or result is the same. Accordingly, given a single piece of information input into each of the control units 306, 326, the same output will result. In this fashion, given the same starting conditions, each predictor can make an estimate of what the next data point should be (with the estimate at each control unit 306, 326 being identical). As used here, the predictor is a software code or firmware code that is saved on an associated memory of the surface control unit 306 or the downhole control unit 326.

The predictor of each control unit 306, 326 is configured to receive, obtain, or be provided with data (e.g., preliminary data) and predict a subsequent value based on this received data. That is, the predictors are configured to predict or estimate a future data value based on starting condition information (e.g., such as the preliminary data or the prior obtained data) and a current (or past) data value. For example, during a drilling operation, measurements are made regarding formation evaluation and drilling performance. Conventionally, this information is processed and transmitted from the downhole control unit 306 to the surface for updating information at the surface control unit 326. The surface control unit 326 may then process the received information to determine if an adjustment to a drilling operation should be changed, or if other action should be taken. The information is typically transmitted by mud-pulse telemetry at specific intervals or on demand by an operator or the like. It will be appreciated that other telemetry operations and mechanisms may be employed without departing from the scope of the present disclosure. For example, alternatives to mud pulse telemetry may include, without limitation, acoustic telemetry and electromagnetic telemetry, which may be used to transmit data from the downhole control unit 326 to the surface control unit 306. It will be appreciated that there may be no cable or wiring that connects between the downhole processor in the downhole control unit 326 executing the downhole predictor and the processor in the surface control unit 306 executing the surface predictor, and thus one or more telemetry mechanisms may be required to transmit data from the downhole control unit 326 to the surface control unit 306.

However, in accordance with embodiments of the present disclosure, when data is received at one of the control units 306, 326 that is intended to be transmitted to the other of the control units 306, 326, the predictor may be used to determine if such transmission is necessary. If the transmission is not necessary, as explained herein, then no transmission is made and thus telemetry bandwidth is not used for transmitting such data. If it is determined that transmission is necessary, then the telemetry communication is performed. Because of the high volume and variety of data collected both at the surface and downhole, each predictor may comprise a plurality of different mathematical algorithms or processes for estimating values associated with the different aspects of drilling. In other embodiments, a number of different predictors may be provided. For example, in some embodiments, each different measurement may be assigned or have a separate and distinct (e.g., dedicated) predictor associated therewith. Further, it will be appreciated that any number of predictors may be implemented without departing from the scope of the present disclosure (e.g., a single-thread version, a multiple thread version, etc.). As used herein, the term “thread” refers to a processing algorithm that takes a known data point (and preliminary data, base line data, base conditions or information, as appropriate) and predicts what a next data point will be.

A single-thread version may use data of a single property, such as a density of a formation. In contrast, a multiple-thread version may use data from more than one property, such as using the density and a resistivity of a formation. The thread(s) may be designed to process operational data (e.g., operational properties) such as drill string configuration (e.g., tool configuration), borehole size, rate of penetration (ROP), revolutions per minute of a drill string (RPM), weight-on-bit applied on the drill string (WOB), depth of the borehole or depth of the drill bit (e.g., measured depth (MD) or true vertical depth (TVD), etc.), borehole inclination or borehole azimuth, and flow rate of the drilling fluid. The threads(s) may alternatively use formation evaluation data (e.g., earth formation properties) such as formation density, formation resistivity, formation porosity, formation permeability, and formation lithology, and/or may use dynamic data (e.g., dynamic property) such as drill string acceleration (e.g., vibration), drill string bending, and strain acting on the drill string. A predictor may combine multiple threads (multiple-thread version of a predictor) or may use only one thread (single-thread version of a predictor).

In accordance with embodiments of the present disclosure, a control unit will not transmit data that can be predicted. At the surface and outside the borehole (e.g., surface control unit 306), a surface predictor, executed by a surface processor, may be used to estimate a future value based on preliminary data, data received from downhole and based on initial or known conditions (such as for example temperature, borehole orientation, depth, drill string acceleration, drill string bending, drill string rotation, drilling fluid flow rate, borehole size, formation properties, rate of penetration, etc.) that may impact the specific measurement. At the same time, downhole and inside the borehole (e.g., downhole control unit 326) the downhole control unit will know what data has been sent to the surface unit (i.e., the data transmitted from downhole to the surface). Further, because the downhole control unit has a downhole predictor, executed by a downhole processor, that is identical to the surface predictor of the surface control unit, the downhole control unit will know how the surface control unit will predict and make decisions. Accordingly, the downhole control unit will know what the prediction value is that is made at the surface. Thus, if the predicted value (calculated both at surface and downhole) is within an acceptable range (for the specific measurement) relative to the actual measurement, then the downhole control unit will not send the actual measurement data. Then, if the measurement data is not received at the surface (when it is expected, i.e., within a certain time window), the surface control unit will assume that the lack of transmission was purposeful, and that the prediction was correct. The surface control unit will then update its information with the predicted value serving as the next data point. If data is received at the surface control unit, the surface control unit will update the information based on the received data and not the predicted value.

In accordance with some embodiments of the present disclosure, the time window may be predetermined. For example, in a non-limiting embodiment, the width or length of the time window may depend on various factors. For example and without limitation, the width or length of the time window may depend upon the type of property of interest that is to be predicted, a data rate of the telemetry, a rate of penetration of the drill string, a sample rate of the measurement of the property of interest downhole (e.g., sample rate of a sensor), a time duration of a transmitted information in a telemetry stream (e.g., a number of bits per information and bit rate), an available bandwidth of the telemetry, etc. In accordance with some embodiments of the present disclosure, the time window may be a few seconds up to a few minutes. For example, and without limitation, the time window may have a width or length of 1 second (s) to 10 s to 30 s, 20 s to 40 s, 30 s to 1 minute (min), 1 min to 10 min, or 5 min to 30 min.

Referring now to FIG. 4 , a schematic illustration of an example process in accordance with an embodiment of the present disclosure is shown. In FIG. 4 , plot 400 a represents data values or data points that are recorded at a surface control unit including a surface processor (e.g., surface control unit 306) and plot 400 b represents data values or data points that are recorded at a downhole control unit including a downhole processor (e.g., downhole control unit 326). In each of plots 400 a, 400 b, the horizontal axis represents time, and the vertical axis is an arbitrary scale for a data value. On each of plots 400 a, 400 b, a series of data points 402, 404 are plotted, with measurement data points 402 and estimate data points 404 indicated.

The measurement data points 402 and the estimate data points 404 are representative of a property of interest (e.g., formation property, drilling characteristic (including dynamic properties and operational properties), or the like). The measurement data points 402 represent actual values obtained by a downhole tool, downhole sensor, downhole system, or the like that are located inside the borehole and below the earth surface. The estimate data points 404 represent predicted values that are generated through processing of information to estimate or guess what a future measurement data point will be. As such, when the estimate data points are 100% accurate, a given estimate data point and a respective given measurement data point will be identical. However, it will be appreciated that the estimate data points may deviate from the measurement data points due to real-world influence, as the estimate values are only estimates based on prior data and/or synthetic data.

As shown in FIG. 4 , at time t₁, the downhole system may obtain a first measurement 402 ₁. In this example, the first measurement value 402 ₁ is the first collected data point of a monitored property of interest, such as a formation measurement and shown in plot 400 b. In this example, no preliminary data is available, such as earlier transmitted measurement values, data known from an offset well, or data resulting from a simulation performed prior to the obtaining the first measurement 402 ₁. The only pre-existing information related to the collected data is information, for example, associated with a tool configuration, or the like. This information does not allow one to derive information on the measurement data collected by a downhole sensor. As such, a prediction of the first measurement value 402 ₁ is not possible, as there is no preliminary data or starting collected information (e.g., earlier measurement data transmitted to the surface unit). Because of this, at time t₁, the downhole control unit will cause telemetry of the first data point 402 ₁ to the surface by means of a first telemetry transmission 406 ₁. As shown on plot 400 a, the surface control unit will receive the first data point 402 ₁. In this example, a single data point may not be sufficient to make a prediction for subsequent data points, and thus at time t 2 the downhole control unit obtains a second measurement value 402 ₂. Because a prediction has not been made, the downhole control unit will transmit the second measurement value 402 ₂ to the surface control unit by means of a second telemetry transmission 406 ₂. The number of data points necessary to perform a reliable prediction of the property of interest may depend on a variety of factors. For example, and without limitation, the number of data points may depend upon the type of property of interest, the operational conditions, and/or the formation (including the borehole, etc.). In some non-limiting configurations, a single (i.e., one) data point may be sufficient to perform a reliable prediction. In other embodiments, more than a single (one) data point may be required, such as two or more data points.

In the downhole control unit, having the first and second measurement values 402 ₁, 402 ₂, a prediction for the next measurement value may be made based on these initial measurement values using the downhole processor executing the downhole predictor. As shown in plot 400 b, the downhole control unit may make a prediction for the third measurement value, indicated as third estimate value 404 ₃. It is noted that the nomenclature used here labels the first estimate to appear as a “third” estimate to align the series of obtained points, there is no “first” or “second” estimate value in this example, as the first and second measurement values could not be predicted or estimated. At the same time, the surface control unit also predicts the third estimate value 404 ₃ as indicated on plot 400 a by using the surface processor and the surface predictor. The third estimate value 404 ₃ is assigned to time t₃. Then, at time t₃ (actual time), the downhole control unit will obtain a third measurement value 402 ₃, as indicated on plot 400 b. The downhole control unit will determine that third telemetry transmission 406 ₃ is close enough to the third estimate value 404 ₃ and thus determine that no transmission is necessary. Accordingly, the third telemetry transmission 406 ₃ will not occur (indicated by the “X” on the telemetry arrow) and the surface control unit will not receive the information of the third measurement value 402 ₃, and thus the third measurement value 402 ₃ does not appear on plot 400 a, rather, the third estimate value 404 ₃ fills that point. The measurement value used by the downhole predictor for comparison with a predicted estimate value may be a raw measurement value, as provided by a sensor, or may be a preprocessed raw measurement value (e.g., preprocessed for noise reduction, amplification, filtering, etc.).

Based on the first three data points (measurement values 402 ₁, 402 ₂, and third estimate value 404 ₃), the surface control unit will predict the next value as fourth estimate value 404 ₄ as shown on plot 400 a. The downhole control unit knows (e.g., has information regarding) that the surface control unit has made a prediction based on these three data points, and thus knows the value of the fourth estimate value 404 ₄, which is plotted on plot 400 b. The downhole control unit knows that the surface control unit has made the prediction based on the three data points because the downhole control unit did not transmit the third measurement value 402 ₃ to the surface unit. Not receiving at the surface control unit, the third measurement value 402 ₃ indicates to the surface control unit that the predicted third estimate value 404 ₃ matches precisely enough with the third measurement value 402 ₃ and can be used for the subsequent prediction. At time t₄, a fourth measurement value 402 ₄ is obtained downhole inside the borehole. The downhole control unit will plot the fourth measurement value 402 ₄ and compare this value to the fourth estimate value 404 ₄. As illustrated in plot 400 b, the fourth measurement value 402 ₄ does not match to the fourth estimate value 404 ₄. This mismatch of values may be based on various criteria, such as, and without limitation, comparison to a threshold deviation, check to confirm the value is above or below a particular absolute value, within a predetermined margin of error, based on a percentage deviation associated with the particular measurement, or the like.

It will be appreciated that the comparison between the measurement value and the estimate value may depend upon the specific data associated therewith. In this case, because the fourth measurement value 402 ₄ deviates from the fourth estimate value 404 ₄, the downhole control unit will transmit the fourth measurement value 402 ₄ to the surface unit by means of a fourth telemetry transmission 406 ₄. The surface control unit will receive the fourth measurement value 402 ₄ and plot such a data point. Further, because the surface control unit received the fourth measurement value 402 ₄, it will delete the fourth estimate value 404 ₄ (indicated by the “X” on such data point in FIG. 4 ) and enter the fourth measurement value 402 ₄ into the surface control unit memory, processing, or data log. A percentage deviation may be in the range of 0.5% to 1%, to 5%, or 1% to 10%, for example, and without limitation.

Based on the data points up to this point (values 402 ₁, 402 ₂, 404 ₃, 402 ₄), the surface control unit will make a prediction for the next data point as indicated by fifth estimate value 404 ₅, as indicated on plot 400 a for time t₅. Similarly, the downhole control unit will make the same estimate, based on the same information, as indicated on plot 400 b. Then, at time t₅, the downhole control unit will obtain the fifth measurement value 402 ₅. In this case, the fifth measurement value 402 ₅ matches the fifth estimate value 404 ₅ within the threshold deviation. As such, in some embodiments, a fifth telemetry transmission 406 ₅ may not be performed, and the surface control unit may fill the entry for t₅ with the fifth estimate value 404 ₅. However, in this illustrative embodiment, even though the fifth measurement value 402 ₅ is within acceptable limits of the fifth estimate value 404 ₅, the downhole control unit sends the fifth measurement value 402 ₅ to the surface control unit, which will plot the fifth measurement value 402 ₅. In some such embodiments, this additional transmission (telemetry transmission 406 ₅) may be used for synchronization purposes, in view of the prior point (at time t₄) not matching between the fourth estimate value 404 ₄ and the fourth measurement value 402 ₄, to confirm that the two systems are operating correctly.

Although FIG. 4 is described with only five total data points, this is merely for example, and the number of data points to establish a base line (e.g., first and second measurement values 402 ₁, 402 ₂) may be greater than two, or potentially less. For example, in some embodiments, a prediction or estimate value may be provided for a first data point depending on the specific metric or property in question and the pre-existing data available to establish a first estimate value. For example, if a current well is being drilling through a formation near other previously drilled wells, then it may be possible to have a first estimate value to estimate a first measurement value from the previously drilled well(s) (e.g., offset well(s)). In this specific example the base line data act as preliminary data enabling the surface predictor to predict the first measurement value.

As discussed above, the process described herein is achieved through the use of identical predictors located at two separate locations. In the disclosed and discussed example, a first predictor is located downhole inside a borehole and below the earth surface emersed in borehole fluid, and a second predictor is located at the surface, outside of the borehole, outside of the bottomhole assembly, and above the earth surface and surrounded by air. Both predictors are configured such that they receive the same information as inputs and will perform the same processing, analysis, or other operations thereon to generate the same output. As such, the first predictor will know what the second predictor will predict/estimate, and thus can make a determination regarding a decision to transmit information by telemetry or not.

The predictors may be software or process elements that are part of a control unit or the like or may be dedicated components configured to receive and process information. The predictors may be based on various types of logic or prediction algorithms, as known in the art. For example, depending on the specific characteristic or property in questions, models, extrapolation algorithms, based on offset well data, historical data, lab or synthetic modeling and testing, or the like may be employed for preforming the prediction of the next data point. As discussed, each predictor will have the same logic or prediction algorithms and same data, and thus the outputs of the two predictors will always be identical. Because the output is known, it can be determined if a measured value is equal to or within some predefined metric (e.g., threshold or the like). When the measured value is equal to or within the predefined metric (e.g., threshold) relative to the estimate value, the predictor or some associated processor may determine that a telemetry transmission is not required. The other predictor (or some associated processor) may monitor for a received signal or telemetry transmission that is associated with the next estimate value. If no such telemetry transmission is received, the second predictor (or associated processor) may determine that the lack of transmission was intentional, and thus the data that was anticipated to be received may be replaced with the estimate value. As such, telemetry may be avoided for such data and bandwidth may not be occupied by transmission of such data. Such reduced bandwidth occupancy can allow for such bandwidth to be used for the transmission of additional and/or alternative data that could not have been telemetered in systems where the measured data must be transmitted due to a lack of the described predictors. Accordingly, some embodiments of the present disclosure may allow for additional or alternative data to be transmitted to the surface that was not previously able to be transmitted due to bandwidth limits.

In accordance with embodiments of the present disclosure, a predictor will make a prediction of a next estimate value and then compare a received measurement value with the estimate value. The comparison may be based on a margin of error, a threshold value, a maximum deviation from a prior value or expected value, comparison relative to an absolute value, or the like, depending on the specific characteristic or property in question. That is, in accordance with embodiments of the present disclosure, one or more predictors may be used for one or more respective characteristics or properties, and each prediction (or each process in a single predictor) may be independently performed, such that multiple parallel processes may be performed to determine what information is required to be transmitted to another predictor or system. As such, the amount of data that is transmitted by telemetry may be reduced through use of the predictors and systems described herein. As such, greater bandwidth may be available for telemetry as less information will be required to be transmitted at any given time.

As noted above, different properties or characteristics may be monitored by respective predictors, logic, or algorithms of a predictor. The properties and characteristics can include, for example and without limitation, gamma ray data, neutron data, ROP data, WOB data, rotary speed data, formation information, directional data such as inclination and azimuthal measurements, dynamic data such as acceleration, vibration (e.g., torsional, lateral, axial), and bending, steering data, or other downhole data related to a formation, a drilling operation, and/or BHA/string component performance. It is noted that these properties are all obtained downhole with the potential for transmission to the surface. However, the opposite may also be true. That is, information may be transmitted from the surface to a downhole control unit. For example, drilling commands or the like may be transmitted from the surface to downhole through a downlink, which is similarly subject to bandwidth limits as an uplink from downhole to the surface. In such a configuration, the two predictors are identically configured and thus a lack of receipt of a transmission may indicate that the next estimate is correct and thus the downhole control unit should continue as planned. This thus avoids additional downlink transmissions, similar to the above-described avoidance of uplink transmissions.

As described above, two processors and two predictors are provided, with a first processor executing a first predictor located downhole inside the borehole and a second processor executing a second predictor located at the surface outside the borehole. However, such a configuration is not intended to be limiting. In other embodiments, both predictors may be located downhole. For example, referring now to FIG. 5 , a schematic illustration of a system 500 in accordance with an embodiment of the present disclosure is shown. The system 500 may be configured for drilling a borehole 502 through the earth formation 504. The system 500 includes a surface assembly, such as shown and described in FIGS. 1 and 3 , including a surface control unit 506. A string 508 is disposed within the borehole 502 and configured to cut through the earth formation 504 using a disintegrating device 510. The disintegrating device 510 may be part of a BHA, as described above.

Proximate the disintegrating device 510 may be a first processor 522 associated with and configured to execute a first predictor 512 (e.g., first downhole processor and first downhole predictor) and a third processor 524 associated with and configured to execute a third predictor 514 (e.g., second downhole processor and second downhole predictor). As described above, the predictors of the present disclosure are software processes, instructions, or code that may be executed by an associated processor. The third predictor 514 and associated processor 524 may be arranged along the string 508 between the first processor 522 and associated first predictor 512 and the surface. The first and third predictors 512, 514 are both downhole predictors. The surface control unit may include a second (or surface) processor 526 associated with and configured to execute a second (or surface) predictor 516. As illustrated, the second processor 526 executing the second predictor 516 is located outside the string 508, and may be located or part of the surface control unit 506. In accordance with some embodiments, there may be no cable or wiring that connects between the first processor 522 in the downhole control unit executing the first predictor 512 and the second processor 526 in the surface control unit 506 executing the second predictor 516.

At each processor 522, 524 526 a pulser, a pressure transducer, or the like may be associated therewith for the purpose of generating and/or detecting pulses in a fluid for the purpose of telemetry. Each of the predictors 512, 514, 516 may be identically configured, such that each predictor 512, 514, 516 will output the same result given the same input. In some embodiments, additional processors associated with and configured to execute additional predictors may be provided along the string 508 or one of the illustrated predictors 512, 514, 516 may be omitted, such that, in some embodiments, both predictors are arranged downhole (e.g., a system with only first and second predictors 512, 514).

In another embodiment, two or three of the processors 522, 524 526 are configured to execute more than one predictor each. In such configurations, each of such predictors executed by a single (or the same) processor are not identical to each other. For example, in such a configuration, the first processor 522 may execute the first predictor 512 and a fifth predictor 532, the second processor 526 may execute the second predictor 516 and a fourth predictor 536, and the third processor 524 may execute the third predictor 514 and a sixth predictor 534. In such a configuration, the first predictor 512 and the second predictor 516 may be identical, the third predictor 514 and the fourth 536 may be identical, and the fifth predictor 532 and the sixth predictor 534 may be identical. As such, the estimate value predicted by the first predictor 512 is equal to the estimate value predicted by the second predictor 516, the estimate value predicted by the third predictor 514 is equal to the estimate value predicted by the fourth predictor 536, and the estimate value predicted by the fifth predictor 532 is equal to the estimate value predicted by the sixth predictor 534. In such a configuration, the second predictor 516 is configured to predict what is measured by the first processor 522 using an associated first sensor 542. The fourth predictor 536 is configured to predict what is measured by the third processor 524 using an associated second sensor 544. The sixth predictor 534 is configured to predict what is measured by the first processor 522 using the associated first sensor 542 or, alternatively, the fifth predictor 532 is configured to predict what is measured by the third processor 524 using the associated second sensor 544. In accordance with some embodiments, the first and third processors 522, 524 may be arranged at or about the same location along a longitudinal axis of the string 508 or may be arranged at different locations along the longitudinal axis of the string.

Referring now to FIG. 6 , a flow process 600 for performing an operation in accordance with an embodiment of the present disclosure is shown. The flow process 600 may be performed using a system as shown and described above. Such a system may include a first predictor at a first location and a second predictor at a second location separate from the first location. In some embodiments, the first predictor may be located in a downhole control unit that may be part of a BHA and the second predictor may be arranged uphole from the first predictor, either along a string of the system or at the surface. As described above, the two predictors are identical such that given the same input they will output the same result. As such, each predictor will respond the same way to the same information/data, allowing for a reduction in telemetry transmissions.

The system used to perform process 600 the predictors implemented in respective controllers and/or control units and includes a telemetry system for communicating between the first predictor and the second predictor (or other components associated therewith). The telemetry system may be a mud-pulse telemetry system that is configured to generate pressure waves within a fluid (e.g., a pulser). Each of the first and second predictors may be associated with a respective pulser for transmitting information and a system to receive pulses from the other system, as will be appreciated by those of skill in the art.

At operation 602, preliminary data is established at each of the first and second predictors. In some embodiments, operation 602 comprises obtaining measurements downhole, such as during a drilling operation. The operation 602 may obtain one or more preliminary data points associated with a characteristic or property that is monitored. In some embodiments, operation 602 may comprise pre-setting initial conditions, such as based on offset wells, laboratory data, synthetic data, modeling, or the like, and thus may not rely on measured data to establish the preliminary data (e.g., base line data). The preliminary data may be stored in a memory associated with the respective predictors.

At operation 604, each of the first and second predictors will generate an estimate value. The estimate value is a predicted value based on the preliminary data from operation 602. Because the first and second predictors are identical, and are provided with the same preliminary data, the estimated values generated at each of the first predictor and the second predictor will be the same. The estimate value may be stored in the memory associated with each respective predictor. The estimate value is a forward-looking prediction of an expected value of a measurement or observation that is performed by a tool, device, system, or the like, associated with a downhole operation.

At operation 606, a measurement value is provided to the first predictor. The measurement value may be obtained using a tool or other system configured to obtain data associated with an operation or component.

At operation 608, the first predictor will compare the received measurement value with the estimate value, and at operation 610 will determine if the measurement value is within a predetermined threshold of the estimate value. The predetermined threshold may be specific to the type of data or measurement. For example, in some embodiments, at operation 608, the threshold maybe a margin of error (±) by percentage, absolute range, or the like. In some embodiments, the threshold comparison may be a check to see if the measurement value exceeds or is below a specific absolute value associated with the property or characteristic. It will be appreciated that operation 608 and the comparison thereof is specific to the type of data or measurement made to obtain the measurement value. The purpose of this comparison at operations 608-610 is to determine if the measurement value is substantially similar to the estimate value such that the estimate value may serve as a valid data point.

Operations 606-610 are performed only at the first predictor. With operation 610 providing a “yes/no” output.

In the event that the comparison at operations 608-610 indicates that the measurement value is within the threshold (“yes”), then the first predictor will save the measurement value and the estimate value. Further, the first predictor will determine that there is no need to transmit the measurement value to the second predictor because the estimate value was valid as a substitute value. Accordingly, at operation 612 the first predictor (or an associated controller/control unit) will not transmit the measurement value to the second predictor. As such, no telemetry transmission is performed. It will be appreciated that in some embodiments and modes of operation, even if the information matches (i.e., estimate value is a valid substitute for the actual value), the telemetry may be performed for the purposes of synchronization or the like. For example, in some embodiments, a preset data transmission may always occur for purposes of synchronization (e.g., every third value may be transmitted). That is, in some embodiments, some preset (or on demand request from surface) may prompt transmission even when the estimate values are valid.

The transmission of synchronization information may include the measurement value, the predicted estimate value, or other kind of information. Other information may include, without limitation, an indicator indicating how well the predicted estimate value matches with the measurement value, such as an indicator for the difference between the measurement value and the predicted estimate value (e.g., percentage, or absolute value). In some embodiments, the synchronization may include the number of predicted estimate values and/or the number of measurement values used by the downhole predictor or the surface predictor since the prediction started. The synchronization may also include a ratio of the number of measurement values and predicted estimated values used in the downhole predictor or the surface predictor since the prediction started. The transmission of the synchronization information may be from the downhole control unit (e.g., downhole control unit 326) to the surface control unit (e.g., surface control unit 306) (i.e., uplink) or from the surface control unit to the downhole control unit (i.e., downlink). In some embodiments, the downhole control unit may be configured to transmit a confirmation indicating to the surface control unit that no measurement value is transmitted to the surface control unit and with the confirmation informing the surface control unit that the estimate value predicted at the surface predictor at the earth surface matches within the predefined threshold with the measurement value collected downhole in the borehole. In this manner, the surface control unit can have a check or confirmation that it did not miss a measurement value (e.g., through bad decoding or distorted data transmission via the telemetry). The indicator may be a ping, such as a 1-bit information or data element within the time window or may be some kind of other coded information (e.g., two of more bits).

At operation 614, the second predictor will monitor for received data associated with the estimate value that may arrive though a telemetry signal. Because the first predictor causes the system to not transmit the measurement value, the second predictor will not receive the measurement value associated with the estimate value. The lack of receipt will indicate to the second predictor that the estimate value is a valid data entry and will save the estimate value in the system as a valid entry for the expected measurement value that never arrived. It will be appreciated that the second processor executing the second predictor or associated component/system will monitor for received telemetry signals. Typically, telemetry is transmitted continuously or at a predefined interval, and thus the second predictor knows when to expect a transmission. As such, the second predictor will know (time window) when a telemetry signal does not arrive, as such signals are expected at known intervals or the like. Accordingly, the second predictor is configured to detect when an expected telemetry does not arrive. As such, when no expected telemetry arrives at the second predictor, the second predictor will update the current entry with the estimate value as a substitute for the measurement value that did not arrive.

Next, the operation will proceed back to operation 604, where the next estimate value is generated by both the first predictor and the second predictor. This subsequent estimate value will be based on the preliminary data in combination with the updated value of the last entry (e.g., the last estimate value generated). The process will then continue in a loop through operations 606-610, and if the result of operation 610 is “yes”, the process will continue through operations 612-614, and again cycle back to operation 604, with each iteration being based on the last updated entry. In the case that the predictive model (including the threads) of the predictors is accurate or within the threshold, it is possible that no telemetry transmissions related to the specific operation/property/characteristic will be sent for some time. As such, bandwidth (data/per time) in the telemetry system will not be occupied by such data, and thus throughput of information may be increased.

If at operation 610, at any point in the cycle (e.g., either the first-time operation 610 occurs or any subsequent time), it is determined that the measurement value is outside the threshold (“no” at operation 610), then the process 600 will proceed to operation 616. At operation 616, the first processor executing the first predictor (or associated component/system/controller/control unit) will cause the measurement value to be transmitted to the second predictor through a telemetry transmission.

At operation 618, the second predictor will receive the measurement value that is received by telemetry, and update the next entry (e.g., current entry) with the measurement value. That is, the estimate value generated at operation 604 (at the second predictor) will be deleted (or stored in a backup memory) and the second predictor will use the received measurement value to generate the next estimate value, when the process 600 returns to operation 604.

In the process 600, and in accordance with embodiments of the present disclosure, the first predictor (whether downhole or at the surface) is the predictor that will receive or generate the initial measurement value. The second predictor only receives such information/value when it is necessary, such as when the measurement value does not match sufficiently with the estimate value. In some embodiments, the first predictor is located downhole inside the borehole and surrounded by drilling fluid, and the telemetry transmission is an uplink, with the second predictor being uphole from the first predictor or located at the surface. In other embodiments or configurations, the first predictor is located at the surface or an uphole position outside the borehole and surrounded by air, and the telemetry transmission is a downlink to the second predictor located downhole therefrom, such as in a BHA or the like. It will be appreciated that each predictor may be both a first predictor and a second predictor, dependent upon the specific direction of transmission and where the measurement value is first obtained. That is, the first predictor, regardless of location, will be the predictor that receives the measurement value, and the second predictor may or may not receive such measurement value depending on the comparison performed at the first predictor.

Furthermore, as noted above, in some embodiments, more than two predictors may be employed in a system. In such embodiments, a single first predictor will typically be present, and the other predictors will each be a second predictor, with each second predictor either receiving or not the measurement value from the first predictor. In other embodiments, the process may be a chain. For example, and without limitation, a first predictor may be located in a BHA. The first predictor may transmit (or not) to a second predictor arranged uphole but not at the surface. The second predictor may become a first predictor after receipt (or not) from the BHA predictor and transmit (or not) to another second predictor that may be uphole or at the surface from this intermediary predictor. The opposite may also be true for downlink communications.

Advantageously, embodiments of the present disclosure allow for improved data management and bandwidth use for telemetry communications. Through the use of at least two identical predictors, determinations of whether data should be transmitted by telemetry may be made. Because the predictors are identical, the same input results in the same output, and thus each predictor will know the values and state of the other predictor. As a result, when predicted (estimate) values are determined to fairly represent a measurement value, the measurement value may not be transmitted, and the estimate value may be entered in lieu of the measurement value, thus eliminating the need to transmit the data.

Because telemetry in downhole environments is bandwidth/packet size limited, improved efficiency of data transmission from downhole to surface (or surface to downhole), as described herein, can improve such data transfer. By not transmitting certain data, the available bandwidth is increased to transmit other data that may be necessary for such transmission, and the unnecessary data is not transmitted. In accordance with some embodiments, a first predictor (processor) at a first location and a second predictor (processor) at a second location are provided, with at least one predictor located downhole. The predictors are configured to perform the same algorithm, processes, methods, models, etc. such that data receive at each predictor is processed in the same manner. Each predictor takes initial data (or prior obtained data), such as the preliminary data, and predicts the next data for the particular downhole measurement. Because the predictors are the same, the “next data” (forward looking, estimate value) will be the same at each predictor. When new data is collected at the first predictor, if the new data is within a predefined margin of error (i.e., matches the prediction), the data is not transmitted. When the second predictor does not receive expected data, the second predictor will assume that the measured data at the first predictor is equal to the predicted value and thus the second predictor will proceed based on the estimate value. In contrast, if at the first predictor, the measured data does not match the prediction, the measured data will be transmitted to the second predictor.

Advantageously, embodiments of the present disclosure allow for selective transmission of data based on predictions of expected measurement values. That is, if a measurement value matches an estimate value, no data is sent, thus freeing up otherwise used bandwidth for telemetry transmissions. Each type of data, measurement, etc. will have an associated error limit that defines what is acceptable or not (i.e., what is a deviation from the prediction to trigger transmission or not).

Set forth below are some embodiments of the foregoing disclosure:

Embodiment 1: A method for predicting downhole measurement data at the earth surface, the method comprising: predicting a first estimate value of a property of interest using a first processor arranged in a downhole tool in a borehole, the first processor executing a first predictor; predicting a second estimate value of the property of interest using a second processor arranged in a surface unit at the earth surface and outside the borehole, the second processor executing a second predictor, the second predictor including identical data processing as the first predictor, such that when the same input is provided to each of the first predictor and the second predictor, the first estimate value predicted at the first processor is equal to the second estimate value predicted at the second processor; obtaining, by a sensor, a measurement value of the property of interest, wherein the sensor arranged in the downhole tool; comparing, at the first processor, the measurement value with the first estimate value predicted by the first predictor; determining if the measurement value is within a predetermined threshold relative the first estimate value; and performing a wellbore operation based on the second estimate value of the property of interest, using the second processor, in response to the measurement value being within the predetermined threshold of the first estimate value.

Embodiment 2: The method of any preceding embodiment, further comprising: transmitting the measurement value from the downhole tool to the surface unit using the first processor in response to the measurement value being outside the predetermined threshold; replacing, by the second processor, the second estimate value with the transmitted measurement value in response to receiving the transmitted measurement value at the surface unit; and predicting a subsequent second estimate value with the second predictor based on the transmitted measurement value.

Embodiment 3: The method of any preceding embodiment, wherein, in response to the measurement value being within the predetermined threshold from the first estimate value, the downhole tool is configured to not transmit the measurement value to the surface unit.

Embodiment 4: The method of any preceding embodiment, wherein the property of interest is one of a characteristic of a drilling operation and an earth formation property.

Embodiment 5: The method of any preceding embodiment, further comprising establishing a set of preliminary data used by each of the first predictor and the second predictor to predict the first estimate value and the second estimate value.

Embodiment 6: The method of any preceding embodiment, wherein the first predictor is configured to use the preliminary data, and the preliminary data include data from two properties, wherein one of the two properties is the property of interest and the other one of the two properties is one of a characteristic of a drilling operation and an earth formation property, and wherein the two properties are different properties.

Embodiment 7: The method of any preceding embodiment, wherein the predetermined threshold is one of a predetermined percentage deviation between the first estimate value and the measurement value, and a predetermined absolute value deviation between the first estimate value and the measurement value.

Embodiment 8: The method of any preceding embodiment, further comprising: predicting a third estimate value of the property of interest, using a third processor arranged in the downhole tool; and predicting a fourth estimate value of the property of interest using a fourth predictor, wherein the third predictor includes identical data processing as the fourth predictor such that when the same input is provided to each of the third predictor and the fourth predictor the predicted third estimate value is equal to the predicted fourth estimate value, and wherein the fourth estimated value is predicted using one of (i) the first processor or (ii) the second processor.

Embodiment 9: The method of any preceding embodiment, wherein the first predictor includes one of a linear regression, a logistic regression, a decision tree algorithm, a gradient boosted model, and a neural network.

Embodiment 10: The method of any preceding embodiment, further comprising a predetermined time window used by the second processor to wait for the measurement value to be transmitted from the downhole tool to the surface unit and, when the measurement value is not received at the surface unit within the predetermined time window, using the second estimate value to perform the wellbore operation.

Embodiment 11: The method of any preceding embodiment, further comprising transmitting, using the first processor, from the downhole tool to the surface unit an indicator indicating to the second processor to use the second estimate value to perform the wellbore operation.

Embodiment 12: The method of any preceding embodiment, further comprising transmitting from the downhole tool to the surface unit synchronization information.

Embodiment 13: A data prediction system for use with downhole operations, the data prediction system comprising: a sensor configured to obtain a measurement value of a property of interest, the sensor arranged on a downhole tool located in a borehole; a first processor arranged in the downhole tool; and a second processor arranged in a surface unit at the earth surface and outside the borehole; wherein the first processor is configured to: receive the measurement value of the property of interest from the sensor; predict a first estimate value of the property of interest by executing a first predictor; compare the first estimate value with the measurement value; and determine if the measurement value is within a predetermined threshold from the first estimate value; and wherein the second processor is configured to: predict a second estimate value of the property of interest by executing a second predictor; and perform a wellbore operation based on the second estimate value when the measurement value is within the predetermined threshold from the first estimate value; wherein the first predictor and the second predictor are configured to perform identical data processing such that when the same input is provided to each of the first predictor and the second predictor, the first estimate value predicted at the first predictor is equal to the second estimate value predicted at the second predictor.

Embodiment 14: The system of any preceding embodiment, wherein the first processor is configured to cause transmission of the measurement value from the downhole tool to the surface unit in response to the measurement value being outside the predetermined threshold.

Embodiment 15: The system of any preceding embodiment, further comprising at least one of a mud pulser, an electromagnetic telemetry device, and an acoustic telemetry device configured to transmit the measurement value from the downhole tool to the surface unit in response to commands received from the first processor.

Embodiment 16: The system of any preceding embodiment, wherein the second processor is configured to replace, in the second predictor, the second estimate value with the transmitted measurement value and to predict a subsequent second estimate value with the second predictor based on the transmitted measurement value.

Embodiment 17: The system of any preceding embodiment, wherein no cable connection exists between the first processor and the second processor.

Embodiment 18: The system of any preceding embodiment, wherein each of the first predictor and the second predictor use preliminary data to predict the first estimate value and the second estimate value, respectively.

Embodiment 19: The system of any preceding embodiment, wherein the predetermined threshold is one of a predetermined percentage deviation between the first estimate value and the measurement value or a predetermined absolute value deviation between the first estimate value and the measurement value.

Embodiment 20: The system of any preceding embodiment, further comprising: a third processor arranged in the downhole tool and configured to predict a third estimate value; and a fourth predictor executed by one of (i) the first processor or (ii) the second processor and configured to predict a fourth estimate value, wherein the third predictor includes identical data processing as the fourth predictor, such that when the same input is provided to each of the third predictor and the fourth predictor, the predicted third estimate value is equal to the predicted fourth estimate value.

The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms “about”, “substantially” and “generally” are intended to include the degree of error associated with measurement of the particular quantity based upon the equipment available at the time of filing the application. For example, “about” and/or “substantially” and/or “generally” can include a range of ±8% or 5%, or 2% of a given value.

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a borehole, and/or equipment in the borehole, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made, and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited. 

What is claimed is:
 1. A method for predicting downhole measurement data at the earth surface, the method comprising: predicting a first estimate value of a property of interest using a first processor arranged in a downhole tool in a borehole, the first processor executing a first predictor; predicting a second estimate value of the property of interest using a second processor arranged in a surface unit at the earth surface and outside the borehole, the second processor executing a second predictor, the second predictor including identical data processing as the first predictor, such that when the same input is provided to each of the first predictor and the second predictor, the first estimate value predicted at the first processor is equal to the second estimate value predicted at the second processor; obtaining, by a sensor, a measurement value of the property of interest, wherein the sensor arranged in the downhole tool; comparing, at the first processor, the measurement value with the first estimate value predicted by the first predictor; determining if the measurement value is within a predetermined threshold relative the first estimate value; and performing a wellbore operation based on the second estimate value of the property of interest, using the second processor, in response to the measurement value being within the predetermined threshold of the first estimate value.
 2. The method of claim 1, further comprising: transmitting the measurement value from the downhole tool to the surface unit using the first processor in response to the measurement value being outside the predetermined threshold; replacing, by the second processor, the second estimate value with the transmitted measurement value in response to receiving the transmitted measurement value at the surface unit; and predicting a subsequent second estimate value with the second predictor based on the transmitted measurement value.
 3. The method of claim 1, wherein, in response to the measurement value being within the predetermined threshold from the first estimate value, the downhole tool is configured to not transmit the measurement value to the surface unit.
 4. The method of claim 1, wherein the property of interest is one of a characteristic of a drilling operation and an earth formation property.
 5. The method of claim 1, further comprising establishing a set of preliminary data used by each of the first predictor and the second predictor to predict the first estimate value and the second estimate value.
 6. The method of claim 5, wherein the first predictor is configured to use the preliminary data, and the preliminary data include data from two properties, wherein one of the two properties is the property of interest and the other one of the two properties is one of a characteristic of a drilling operation and an earth formation property, and wherein the two properties are different properties.
 7. The method of claim 1, wherein the predetermined threshold is one of a predetermined percentage deviation between the first estimate value and the measurement value, and a predetermined absolute value deviation between the first estimate value and the measurement value.
 8. The method of claim 1, further comprising: predicting a third estimate value of the property of interest, using a third processor arranged in the downhole tool; and predicting a fourth estimate value of the property of interest using a fourth predictor, wherein the third predictor includes identical data processing as the fourth predictor such that when the same input is provided to each of the third predictor and the fourth predictor the predicted third estimate value is equal to the predicted fourth estimate value, and wherein the fourth estimated value is predicted using one of (i) the first processor or (ii) the second processor.
 9. The method of claim 1, wherein the first predictor includes one of a linear regression, a logistic regression, a decision tree algorithm, a gradient boosted model, and a neural network.
 10. The method of claim 1, further comprising a predetermined time window used by the second processor to wait for the measurement value to be transmitted from the downhole tool to the surface unit and, when the measurement value is not received at the surface unit within the predetermined time window, using the second estimate value to perform the wellbore operation.
 11. The method of claim 1, further comprising transmitting, using the first processor, from the downhole tool to the surface unit an indicator indicating to the second processor to use the second estimate value to perform the wellbore operation.
 12. The method of claim 1, further comprising transmitting from the downhole tool to the surface unit synchronization information.
 13. A data prediction system for use with downhole operations, the data prediction system comprising: a sensor configured to obtain a measurement value of a property of interest, the sensor arranged on a downhole tool located in a borehole; a first processor arranged in the downhole tool; and a second processor arranged in a surface unit at the earth surface and outside the borehole; wherein the first processor is configured to: receive the measurement value of the property interest from the sensor; predict a first estimate value of the property of interest by executing a first predictor; compare the first estimate value with the measurement value; and determine if the measurement value is within a predetermined threshold from the first estimate value; and wherein the second processor is configured to: predict a second estimate value of the property of interest by executing a second predictor; and perform a wellbore operation based on the second estimate value when the measurement value is within the predetermined threshold from the first estimate value; wherein the first predictor and the second predictor are configured to perform identical data processing such that when the same input is provided to each of the first predictor and the second predictor, the first estimate value predicted at the first predictor is equal to the second estimate value predicted at the second predictor.
 14. The system of claim 13, wherein the first processor is configured to cause transmission of the measurement value from the downhole tool to the surface unit in response to the measurement value being outside the predetermined threshold.
 15. The system of claim 14, further comprising at least one of a mud pulser, an electromagnetic telemetry device, and an acoustic telemetry device configured to transmit the measurement value from the downhole tool to the surface unit in response to commands received from the first processor.
 16. The system of claim 14, wherein the second processor is configured to replace, in the second predictor, the second estimate value with the transmitted measurement value and to predict a subsequent second estimate value with the second predictor based on the transmitted measurement value.
 17. The system of claim 13, wherein no cable connection exists between the first processor and the second processor.
 18. The system of claim 13, wherein each of the first predictor and the second predictor use preliminary data to predict the first estimate value and the second estimate value, respectively.
 19. The system of claim 13, wherein the predetermined threshold is one of a predetermined percentage deviation between the first estimate value and the measurement value or a predicted absolute value deviation between the first estimate value and the measurement value.
 20. The system of claim 13, further comprising: a third processor arranged in the downhole tool and configured to predict a third estimate value; and a fourth predictor executed by one of (i) the first processor or (ii) the second processor and configured to predict a fourth estimate value, wherein the third predictor includes identical data processing as the fourth predictor, such that when the same input is provided to each of the third predictor and the fourth predictor, the predicted third estimate value is equal to the predicted fourth estimate value. 